To obtain hydrocarbons such as oil and gas, boreholes are drilled by rotating a drill bit attached at a drill string end. A large proportion of the current drilling activity involves directional drilling, i.e., drilling deviated and horizontal boreholes to place a wellbore as required, to increase the hydrocarbon production and/or to withdraw additional hydrocarbons from the earth's formations. Modern directional drilling systems generally employ a drill string having a bottomhole assembly (BHA) and a drill bit at end thereof that is rotated by a drill motor (mud motor) and/or the drill string. A number of downhole devices placed in close proximity to the drill bit measure and control certain downhole operating parameters associated with the drill string. Such devices typically include sensors for measuring downhole temperature and pressure, azimuth and inclination measuring devices and a resistivity measuring device to determine the presence of hydrocarbons and water. Additional downhole instruments, known as logging-while-drilling (“LWD”) tools, are frequently attached to the drill string to determine the formation geology and formation fluid conditions during the drilling operations.
Most hydrocarbon wellbores are currently drilled using a combination of rotary and hydraulic energy sources. Rotation of the drill string is often used as at least one source of the rotary energy. Drilling fluid, or “mud,” is used to clean the bore hole and drill bit and to cool and lubricate the drill bit. Because the drilling fluid is pump downhole under pressure, the drilling fluid is often used as an additional source of energy for driving drilling motors that provide some or all of the rotary power required to drill the borehole. Different BHAs are selected depending on the nature of the wellbore ‘directional path’ and the method by which the wellbore is being drilled (e.g., pure rotary, rotary with downhole motor, or only a downhole motor). Certain BHAs are configured to allow the wellbore to be steered along a pre-determined path. In steered wellbore path drilling, drilling motors or other devices are configured in one or more ways to facilitate controlled steering of the wellbore. In these BHAs, the drill bit is usually connected to a ‘drive-shaft’ that is supported and stabilized by a series of axial and radial bearings. A drilling motor is used to turn the drive shaft that then turns the bit. The configuration of the motor housing containing the drive-shaft (typically referred to as the bearing housing) and its relationship the remainder of the BHA and drill string allows the well bore to be steered. These motor-based directional BHAs are typically referred to as steerable motor systems.
In recent times, a modification to the motor bearing housing configuration has been introduced to the drilling marketplace. These systems are commonly known as rotary steerable systems. These systems were originally driven or powered by rotation of only the drill pipe, but certain systems presently available combine downhole motors and rotation of the drill string.
Boreholes are usually drilled along predetermined paths and the drilling of a typical borehole proceeds through various formations. To design the path of a subterranean borehole to be other than linear in one or more segments, it is conventional to use “directional” drilling. Variations of directional drilling include drilling of a horizontal, or highly deviated, borehole from a primary, substantially vertical borehole, and drilling of a borehole so as to extend along the plane of a hydrocarbon-producing formation for an extended interval, rather than merely transversely penetrating its relatively small width or depth. Directional drilling, that is to say varying the path of a borehole from a first direction to a second, may be carried out along a relatively small radius of curvature as short as five to six meters, or over a radius of curvature of many hundreds of meters. In many directional boreholes, the well path is a complex 3D curve with multiple radii of curvature. The variation of the curvature (radius) depends upon the pointing (aiming) and bending of the BHA.
Some arrangements for effecting directional drilling include positive displacement (Moineau) type motors as well as turbines that are employed in combination with deflection devices such as bent housing, bent subs, eccentric stabilizers, and combinations thereof. Such arrangements are used in what is commonly called oriented slide drilling. Other steerable bottomhole assemblies, commonly known as rotary steerable systems, alter the deflection or orientation of the drill string by selective lateral extension and retraction of one or more contact pads or members against the borehole wall.
Referring initially to FIG. 1, there is shown a flowchart for an exemplary conventional rotary steering control system 10 for a rotary steerable directional drilling assembly. An intelligent control unit 12 evaluates directional data 14 using programmed instructions 16 and transmits signals 18 as necessary to align the rotary steerable bottomhole assembly with the required well path. With conventional rotary steerable steering systems, there is a time lag between the transmission of the command signals 16 and corresponding physical change of the BHA elements that influence the drilling direction. This time lag is largely attributable to the mechanical and electrical architecture of conventional rotary steering units representatively shown as 20. These conventional rotary steering units 20 employ a number of subsystems 22a-i for effecting a change in drilling direction 24. For instance, in one arrangement, subsystem A may be a valve assembly that opens to control hydraulic fluid flow; subsystem B may be a hydraulic chamber that is filled by hydraulic fluid flowing through the valve assembly; subsystem C may be a piston and associated linkages that converts hydraulic pressure in the hydraulic chamber to translational movement; and subsystem D can be an arm or pad that applies a force on a wellbore wall in response to the movement of the piston and associated linkages. In another arrangement, subsystem A can be an electrical circuit that closes to energize an electrical motor within a subsystem B. Subsystem C can be a gear drive that converts motor rotation into translational movement and subsystem D can be mechanism that adjusts the position of a bit in response to the actuation of the gear drive.
The steering control system 10 shown in the FIG. 1 flow chart is merely a generic representation of conventional rotary steerable BHA assemblies wherein all the elements of the system 10 are packaged within the BHA. Limited commands such as a redirection adjustment of target can be sent from the surface. However, the typical rotary steerable BHA is self sufficient from a decision and tool configuration change/adjustment implementation stand point on a moment by moment basis.
The use of multiple subsystems 22a-i, whether mechanical, electromechanical or hydraulic, can cause hydraulic and mechanical time lags for at least two reasons. First, these conventional subsystems must first overcome system inertia and friction upon receiving the command signal. For instance, motors whether electrical or hydraulic require time to wind up to operating speed and/or produce the requisite motive force. Likewise, hydraulic fluids take time to build pressure sufficient to move a reaction device such as a piston. Second, each interrelated subsystem introduces a separate time lag into the response of the conventional rotary steering drilling system. The separate time lags accumulate into a significant time delay between the issuance and execution of a command signal. In conventional rotary steerable systems, up to several tenths of a second can separate the issuance of a command signal and a corresponding change in drilling direction forces or system geometry that influences drilling direction. If these time lags are great enough relative to drill string RPM and rate of penetration, a reduction in directional control and expected borehole curvature can occur. This can result in a reduction in directional control.
Other configurations of rotary steerable drilling systems minimize the dependency on response time by using a non-rotating stabilizer or pad sleeve. Introduction of the non-rotating (or slow rotating) sleeve decreases the actuation speed requirement but increases the complexity of the steering unit (e.g., the need for rotating seals, rotary electrical connections, etc.). Thus, conventional rotary steerable systems have a limited mechanical response rate, are mechanically complex, or both.
The present invention addresses these and other needs in the prior art.